Method for Increasing Productivity of Hydraulically Fractured Wells

ABSTRACT

Method is provided for increase production rate and improving economics of hydraulic fracturing of a well where a fracture can be formed extending a greater distance than the thickness of the pay zone in the well. A settling fluid containing proppant is injected to form a bank or pile of proppant that extends beyond the pay zone.

BACKGROUND OF INVENTION

1. Field of the Invention

This invention relates to hydraulic fracturing of wells. Morespecifically, method is provided for increasing the flow capacity of ahydraulic fracture around a well (Fracture Flow Enhancement), therebyincreasing the value of the well.

2. Description of Related Art

Hydraulic fracturing is an established technology that has made possiblerecovery of hydrocarbons from wells that would not be economic to drillwithout the availability of the fracturing process. It has also improvedthe economics of gas and oil recovery operations in many other wells.

After a well is drilled to a pre-determined depth to penetrate one or aseries of pre-determined “pay” formations (formations containingproducible hydrocarbons), pipe (casing) is inserted into the drilledhole, and then cement is placed at pre-determined intervals in theannular space between the outside of the pipe and the drilled hole; thecement is placed for the purpose of preventing flow of fluids in thepenetrated formations from entering the wellbore or flowing betweenformations.

If the pipe is adjacent to (passes through) one or more pay formations,methods are then employed to create communicative flow paths from thepay zones to the wellbore. These methods may be applied on a single payor several of them. They are done by creating openings (perforations) inthe pipe and the cement adjacent to the pay and that penetrate into thepay. There are several well known methods used to create theseperforations.

FIGS. 1( a), (b) and (c) depict three typical sketches of currentpractices for inserting casing, cementing and perforating wells. In FIG.1( a), casing penetrates the entire pay zone. In FIG. 1( b), casing onlypartially penetrates the pay zone. FIG. 1( c) illustrates an open holecompletion, where the pipe does not penetrate the pay zone, or much ofit (often referred to as a “topset” completion).

After the above processes are completed, it is a common practice tohydraulically fracture the well. This process has been used in the oiland gas industry since the late 1940's. The hydraulic fracturing processinvolves injecting a fluid (liquid, foam, gas, etc.) to create afracture in a subsurface geological formation that contains the pay. Atsome time during the process a proppant is blended with the fluid tocreate slurry, such that the slurry extends the fracture penetration(both laterally and vertically), transports the proppant into and alongthe fracture, and out to some distance away from the wellbore. The fluidin the slurry is designed such that when the slurry injection isstopped, the fluid leaks off into the pores of formations adjacent tothe fracture and the fracture walls close on the proppant. The proppantis left in the fracture to hold the fracture open and form a highlyconductive path to allow oil or gas to more easily flow from theextremities of the pay into the well. Normal practice is to placeproppant over the pay zone.

The determination or design of how much of what fluid and how much ofwhat proppant and the injection rate required for a treatment depends ona priori knowledge of (1) the profile of in situ properties of theformations that control the geometry (dimensions and shape) of thepropagating fracture, and (2) the permeability of the pay, which impactsthe required fracture size and fracture conductivity required to achievea desired production folds-of-increase from the treatment. Knowledge ofthe profile of in situ properties of a formation is typicallyascertained using down hole well log surveys, from which formationlithologies and the mechanical rock properties (such as formationPoisson's Ratios and Young's Moduli can be interpreted.

Stress profiles, which impact vertical fracture height, are routinelycalculated from Poisson's Ratios. Fracture widths, which impact fractureconductivity, are impacted by both in situ stress and Young's Modulus.Hence, knowledge of these properties is essential in the credible designof a fracturing treatment. These treatment designs are typically doneusing a computer model to calculate the treatment design required toarrive at a required fracture penetration geometry and required fractureconductivity which will yield a desired production folds of increase(FOI).

The required fracture conductivity is typically ascertained from wellestablished approaches that incorporate fracture conductivity withformation permeability, pay thickness, and fracture penetration lengthto calculate production folds-of-increase (FOI). These are documented indescribed in the Society of Petroleum Engineers, Monograph, Volume 12:Recent Advances in Hydraulic Fracturing, by John L. Gidley, Stephen A.Holditch, Dale E. Nierode, and Ralph W. Veatch, Jr., Copyright 1989,ISBN 1-55563-020-0.

All approaches have the commonality that the calculated production FOIresults are normalized on net pay thickness. That is the approachesassume that the fracture conductivity is effective only over the paythickness. Hence, because of this assumption, it is atypical to design afracturing treatment where more proppant is used than is required tocover the pay, the reason being that the well-established production FOIcalculations do not make the benefits apparent for increasing fractureconductivity beyond the extent of the net pay. Normally fracturetreatments are not intentionally designed to have settled proppant packsthat extend significantly above the top of the pay. Normally designs arefor the settled proppant pack to at least reach the top of the pay, andusually not extend more than one-half of the pay thickness above the topof the pay. In the prior art, if proppant packs were designed to extendabove the pay, by any amount, it was to ensure that the entire pay wascovered, rather than to achieve a benefit from additional fractureconductivity.

Herein lies the novelty of this invention. It addresses the benefits ofincreasing fracture conductivity beyond the extent of the pay. Themethod for doing that is to design treatments with sufficient proppantvolumes to create additional fracture conductivity beyond the extent ofthe pay.

Although improvements in proppants have been made by providing higherstrength proppants, such that the flow conductivity of fractures hasbeen increased, there is still a need for hydraulic fractures aroundwells that allow higher flow rates of fluids at given pressureconditions in and around the well.

BRIEF SUMMARY OF THE INVENTION

Method is provided for forming a proppant pack in a fracture around awell that makes possible higher flow rate into the well by increasingthe vertical height of the proppant pack beyond the pay zone to beproduced.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)

FIGS. 1( a), (b) and (c) are sketches of current practices for placingcasing or leaving an open hole for well completions.

FIGS. 2( a), (b) and (c) illustrate in situ stress, Poisson's ratio andelastic modulus magnitudes versus depth for a base case illustration.

FIGS. 3( a), (b) and (c) depict the in situ stress profile versus depth,along with the fracture half-width versus depth profile for the basecase, where the fracture penetration length, Xf, has reached a distanceof 1190 feet from the wellbore. The Xf versus depth profile is artisticlicense, for the sake of differentiating it from other lines in thefigure. The computer generated fracture vertical height value is thatshown where the fracture intersects the wellbore at Xf equals 0 feet,and the height remains constant from the wellbore to Xf equals 1190feet.

FIG. 4 shows base case proppant requirements vs fracture penetration.

FIG. 5, shows base case predicted folds-of-increase of production ratevs fracture penetration.

FIG. 6 shows base case predicted pre- and post-frac production vs timeas predicted for each of the proppants; for this depiction all valuesare for an Xf equal to 1190 feet.

FIG. 7 illustrates base case present value increase vs fracturepenetration.

FIG. 8 shows base case fracturing costs vs fracture penetration.

FIG. 9 shows base case npvf vs fracture penetration.

The preceding figures, along with the corresponding discussionconstitute the Base Case scenario that is used as a basis for comparisonwith the Fracture Flow Enhancement (FFE) process disclosed herein.

FIG. 10( a) shows calculated fracture half-width vs depth for a proppantpile at the top of pay when the fracture penetration length, Xf, hasreached 1190 feet. FIG. 10( b) shows fracture length vs. depth. Again,the Xf versus depth profile is artistic license; the computer generatedfracture vertical height value is that shown where the fractureintersects the wellbore at Xf equals 0 feet, and the height remainsconstant to Xf equals 1190 feet. Also shown are the vertical extents ofthe pay, the vertical extent of the wellbore connection to the pay andthe proppant pack top is at the pay top. In FIG. 10, the connectionsfrom the wellbore to the fracture are equivalent to the pay.

FIG. 11 shows a proppant pile 100 ft above the top of pay.

FIG. 12 shows a proppant pile 200 ft above the top of pay.

FIG. 13-A shows the change (increase/decrease) in proppant quantityrequirements vs proppant pile above or below the top of pay. FIG. 13-Bshows the change (increase/decrease) in proppant costs vs proppant pileabove or below the top of pay.

FIG. 14 shows the predictions for percent change from the base casescenario in production rate folds of increase (FOI) for proppant packsthat range from 20 feet below the top of the pay to 180 feet above thetop of the pay.

FIG. 15 shows the change in NPVJ vs proppant pile above or below the topof pay.

DETAILED DESCRIPTION OF THE INVENTION

Some fracturing fluids have high viscosity at reservoir conditions andtransport proppant for long distances away from a wellbore. The proppantmay not settle for a significant distance in the fracture before thefracture closes. In this case, if the fracture extends above or belowthe pay zone, the proppant will be left above or below the pay zone inthe fracture. Other fracturing fluids have low viscosity in the fractureand allow proppant to settle to the bottom of the fracture duringpumping or before the fracture closes (herein “settling fluid”). Most orall the proppant is then located in a proppant pack at the bottom of thefracture, and the width of the proppant pack in the fracture is near thewidth of the fracture. Normally, the quantities of materials (fluid andproppant) used in fracturing processes are designed to create conductivefractures that cover the vertical extent of the pay and that do notextend significantly beyond the pay into formations above the top of thepay. In many cases, when a settling fluid is used the vertical extent ofthe proppant pack may not exceed ten percent of the pay thickness.

The vertical extent of a fracture is limited by variations of stress inthe earth. Pay zones typically have lower horizontal earth stress andshale or impermeable zones have higher stress. The higher stress zoneslimit the vertical height of a hydraulic fracture. FIG. 2( a)illustrates stress vs depth in a well and the pay zone of the well(determined by electric or other logs). Sonic logs of the well are usedto calculate Poisson's Ratio (FIG. 2( b)) and Young's Modulus (FIG. 2(c)) of rock around the well, from which stress and fracture width are iscalculated. Stress profiles, which impact vertical fracture height, areroutinely calculated from Poisson's Ratios. Fracture widths, whichimpact fracture conductivity, are impacted by both in situ stress andYoung's Modulus.

When a predicted stress profile in a well is obtained, a hydraulicfracturing treatment may be designed to form a fracture having aselected height, which depends on the stress profile as well as theproperties of the fracturing fluid and the pumping rate during thetreatment. For example, using the stress profile of FIG. 2( a), which isthe same in FIG. 3( a), a fracturing treatment may be designed thatextends a considerable vertical distance above the pay zone. Using asettling fluid for the treatment, and by controlling the total quantityof proppant injected, the vertical extent of the proppant pack can becontrolled.

Using the method disclosed herein, where the vertical extent of thefracture exceeds the vertical extent of the pay, the top of the proppantpack in the fracture, in the vicinity of the wellbore can be controlled.If the vertical extent of the fracture is significantly larger than thatof the pay, a treatment may be designed to have a settled proppant packthat extends well above the pay. This would provide additional fractureconductivity for fluids to flow to the wellbore. Normally fracturetreatments are not intentionally designed to have settled proppant packsthat extend significantly above the top of the pay. Normally designs arefor the settled proppant pack to at least reach the top of the pay, andusually not extend more than one-half of the pay thickness above the topthe top of the pay. However, the vertical extent of the top of theproppant pack in the fracture is limited only by the upward verticalextent of the fracture. This disclosure is to take advantage ofopportunities where it is possible to create proppant packs withvertical extents well beyond the pay interval (above it, or below it, orboth) so as to provide more fracture conductivity, and thus increase theflow rate from the pay to the wellbore.

Normally, connections from the wellbore to the fracture do not extendsignificantly beyond the extremities of the pay, either above it orbelow it more than one-tenth the thickness of the pay interval. Theremay be portions of the pay that overlie and/or underlie intervals thatare considered “economical pay,” but are not connected for economicalreasons. There may be portions of the pay that overlie and/or underlieintervals that are considered “economical pay,” but are not connectedfor other reasons—for example water or gas bearing intervals that mayconstitute undesirable consequences if they are connected. Suchintervals are not considered as pay intervals, for whatever reason, bythose associated with the well.

Using the method disclosed herein, connections from the wellbore to thefracture extend more than ten percent beyond the vertical extent of thepay; either above it, below it, or both above and below it. The fractureconductivity, producing rate, total production, and monetary benefits ofthe Fracture Flow Enhancement (FFE) process disclosed herein derive fromeither one or both of the following:

-   -   (1) increasing the conductive path for fluids residing in the        entirety of the pay to travel through the fracture to the        wellbore.    -   (2) connecting the wellbore to the fracture above and below the        pay, so as to increase the flow from the pay into the wellbore.

EXAMPLE

An example is included to demonstrate the procedure, and the potentialproduction and monetary benefits of the procedure. Computer programswere used to generate the example. These programs are the property ofSoftware Enterprises, Inc., of Tulsa, Okla. They comprise the fracturingtechnology described in the Society of Petroleum Engineers, Monograph,Volume 12: Recent Advances in Hydraulic Fracturing, by John L. Gidley,Stephen A. Holditch, Dale E. Nierode, and Ralph W. Veatch, Jr.,Copyright 1989, ISBN 1-55563-020-0 R. W., 1988. They are provided toparticipants in hydraulic fracturing industry schools taught by theRalph W. Veatch, Jr., and are publically available, at a fee, uponrequest to Software Enterprises, Inc. The example is for a typical oilwell, producing from a 100 foot thick pay that lies at a depth between7400 and 7500 feet. The formation intervals above 7100 feet and below7525 feet impose significant vertical fracture growth inhibition. It waspredicted that a fracture extending 560 feet vertically can be producedby pumping 846,000 gallons of aqueous, borate cross linked, 35 lb/1000gallon guar polymer fluid at a rate of 30 barrels per minute. Thisfracturing procedure thus allows placement of proppant in a fractureextending significantly outside the pay zone.

The formation properties, mechanical rock properties, in situ stressprofile, pipe, connection, cost, oil price ($65/bbl), taxes (15%),royalties (⅛), operating costs ($1000/month), etc., data used for theexample came from actual field cases, but the sources are not confinedto those of a particular well. The fracturing material property andbehavior data used are commensurate with current fracturing design andprediction practices.

For this example, the well is identified as the 17.8.1 well. The resultsand predictions generated for the 17.8.1 well base case scenario by thecomputer models are posed as ground truth for comparing the base casescenario to the FFE scenario to demonstrate the potential benefitsderivable from FFE.

The Base Case

FIGS. 2( a), (b) and (c) illustrate the base case in situ stress & rockproperty profiles that are used to illustrate the principles of theinvention disclosed herein. FIG. 2( a) shows in situ stress, FIG. 2( b)shows Poisson's ratio and FIG. 2( c) shows elastic modulus magnitudesversus depth. These are properties that govern the fracture geometry asit propagates both laterally and vertically into the formations.

FIG. 3( a) depicts the in situ stress profile, FIG. 3( b) the fracturehalf-width versus depth profile and FIG. 3( c) the penetration lengthdistance (1190 feet) from the wellbore (which is denoted by the symbolXf in this and subsequent figures). The Xf versus depth profile isartistic license, for the sake of differentiating it from other lines inthe figure. The computer generated fracture vertical height value isthat shown where the fracture intersects the wellbore at Xf=0 feet, andthe height remains constant to Xf=1190 feet.

TABLE 1 Conductivity TEST Data: @ 5,030 psi In Situ Stress & 150° F.Pack In Situ Effective Proppant Prop Width Cond. Perm. Description:Conc. KfWf Wf@C % KfWf Kf Size/Type SpGr lb/ft² md-ft in Dam'g md-ftDarcy's 20/40 Ottawa Sand 2.65 3.00 2900 0.346 95.0% 145  5 20/40 ResinCoated Sand 2.55 3.00 4800 0.360 90.0% 480 16 20/40 Int. Density 3.203.00 6000 0.287 90.0% 600 25 20/40 Sintered Bauxite 3.58 3.00 6500 0.25685.0% 975 46

Table I contains base case propping agent (proppant) data for the fourtypes of proppants used in the example. The symbol kfwf represents thefracture conductivity of the proppant pack at the various conditionsshown. The in situ values are those used in the computer calculations.

FIG. 4 shows the proppant quantities required for four proppants andconcentrations indicated in the figure as the fracturing procedureextends fracture penetration to lengths Xf.

FIG. 5 shows the predicted production folds-of-increase (FOI) that wouldresult for the fracture penetrations of Xf. FOI represents the ratio ofpost-fracturing producing rate to pre-fracturing (not-fractured)producing rate for the same four proppants and concentrations.

FIG. 6 shows the pre-fracturing producing rate decline over time and thepost-fracturing producing rates over time as predicted for each of theproppants.

FIG. 7 shows the increase in present value, at 15% discount rate, ofproduction from the well for different values of fracture penetrationfor each of the proppants.

FIG. 8 shows the material and pumping cost requirements as thefracturing procedure extends fracture penetration to lengths Xf for eachof the proppants.

FIG. 9 shows the predicted net present value (NPVf) at 15% discountrate, of production from the well that would result from fracturepenetrations of Xf. NPVf represents the discounted value of theproduction flow stream over time after the fracturing costs, productiontaxes, royalties and operating costs have been subtracted from theproduction income. The fracturing treatment data pertinent to FIG. 9 arecontained in TABLE 2

TABLE 2 Prop Fracture Geometry Fluid Prop Quantity Fracturing Costs NetReturns Xf Hf Wfp Vol Conc M-Lbs Fluid Prop Pmp/Fxd Tot NPVf ft ft InM-Gal ppg % Hf Adj (MS) (MS) (MS) (MS) (MS) DROI 20/40 Ottawa Sand: 2.65sp.gr., & L.T. - Kf = 5 Darcy's @ 3.0 lbs/sqft 300 480 0.42 100 6.3 16577 19.8 42.0 138 8751 63.2 600 511 0.36 213 5.7 299 163 35.9 42.0 2419528 39.5 890 536 0.40 442 5.1 525 339 63.1 45.2 447 9559 21.4 1190 5600.44 846 4.4 835 649 100.3 45.2 794 9423 11.9 20/40 Resin Coated Sand:2.55 sp.gr., & L.T. - Kf = 16 Darcy's @ 3.0 lbs/sqft 300 480 0.42 1006.1 159 77 74.7 42.0 193 17834 92.2 600 511 0.36 213 5.5 288 163 135.242.0 340 19623 57.6 890 536 0.40 442 4.9 506 339 238.0 45.2 622 2012732.4 1190 560 0.44 846 4.3 805 649 378.4 45.2 1072 20307 18.9 20/40 Int.Density: 3.20 sp.gr., & L.T. - Kf = 25 Darcy's @ 3.0 lbs/sqft 300 4800.42 100 7.6 199 77 133.5 42.0 252 21824 86.5 600 511 0.36 213 6.9 361163 241.7 42.0 447 24168 54.1 890 536 0.40 442 6.2 635 339 425.7 45.2810 24924 30.8 1190 560 0.44 846 5.3 1010 649 676.7 45.2 1370 25248 18.420/40 Sintered Bauxite: 3.58 sp.gr., & L.T - Kf = 40 Darcy's @ 3.0lbs/sqft 300 480 0.42 100 8.5 223 77 205.1 42.0 324 27558 85.1 600 5110.36 213 7.7 404 163 371.2 42.0 577 30882 53.6 890 536 0.40 442 6.9 711339 653.9 45.2 1038 32128 31.0 1190 560 0.44 846 6.0 1130 649 1039.645.2 1733 32778 18.9

Table 2 shows a summary of the predicted fracture penetrations, fracturevertical heights, average fracture widths, material requirements,material costs, total fracturing costs, net present value returns anddiscounted returns on investments for the four proppants used in thestudy. These are shown for four fracture penetration lengths.

The preceding figures, along with the corresponding discussionconstitute the base case scenario that is used as a basis for comparisonwith the FFE.

The Fracture Flow Enhancement (FFE) Cases

These are predictions for three scenarios of the FFE:.the first is wherethe top of the proppant pack is at the top of the pay, the second iswhere the top of the proppant pack is 100 feet above the top of the pay,and the third is where the top of the proppant pack is 200 feet abovethe top of the pay in the first scenario, the connections from thewellbore to the fracture are equivalent to the pay. In the second andthird scenarios, the connections extend to or beyond the vertical extentof the fracture, to assure that there is a connection between thefracture and the wellbore. All parameters in the Base Case scenario areused in the FFE scenarios except for those changed for the parametricstudies in the FFE scenarios. In all three scenarios, the fracturingfluid quantity requirements are equivalent. The total amount of fluid isthe same for the base case and the three scenarios. The fracturegeometry is governed primarily by the in situ stress and mechanical rockproperties and the rheological behavior of the slurry injected. Studiesby the applicant have indicated that changes in the proppant quantitiesinjected do not alter the results to any degree of significance from thebase case scenario. These proppant quantities are obtained, orcontrolled, by adjusting the proppant concentrations of the injectedslurry.

FIG. 10 shows the first FFE scenario. It depicts the fracture half-widthversus depth profile, and the penetration length distance (1190 feet)from the wellbore (denoted by the symbol Xf). Again, the Xf versus depthprofile is artistic license, the computer generated fracture verticalheight value is that shown where the fracture intersects the wellbore atXf=0 feet, and the height remains constant to Xf=1190 feet. Also shownare the vertical extents of the pay, the vertical extent of the wellboreconnection to the pay and the top of the proppant pack.

FIG. 11 shows the second FFE scenario with the proppant pile 100 FTabove top of pay. The depiction is consistent with that shown in FIG.10, with the top of the proppant pack at 100 feet above the top of thepay.

FIG. 12 shows the third FFE scenario with the proppant pile 200 FT abovetop of pay. The depiction is consistent with that shown in FIG. 10, withthe top of the proppant pack at 200 feet above the top of the pay.

FIG. 13-A shows predictions for proppant quantity requirements forproppant packs that range from 25 feet below the top of the pay to 200feet above the top of the pay. FIG. 13-B shows predictions for thechange (delta) in proppant costs for proppant packs that range from 20feet below the top of the pay to 180 feet above the top of the pay.

FIG. 14 shows the predictions for percent change from the base casescenario in production rate folds of increase (FOI) for proppant packsthat range from 25 feet below the top of the pay to 300 feet above thetop of the pay. Note that a proppant pile or bank extending 200 feetabove the pay increases the production rate FOI by about 30 per cent. Aproppant pile extending 50 ft (1.5 times the pay thickness) above thepay (100 ft) increases FOI about 10 per cent. Normally, an operatorwould seek an increase of at least 10 percent for the additionalengineering and materials used for a fracturing treatment. Therefore, alower limit for increasing the height of a proppant bank above the payis preferably set at 1.5 times the pay thickness.

FIG. 15 shows the predictions for monetary net present return (NPVf)changes from the base case scenario for proppant packs that range from25 feet below the top of the pay to 200 feet above the top of the pay.Under most favorably conditions, the present value of the well isincreased by about $12 million, with a proppant pile above the pay adistance of twice the thickness of the pay. The slope of the curve isstill upward at this distance.

In view of the results, as shown the example, application of the FFEconcurrently with fracturing processes offers the potential ofincreasing enhancement of the fracture conductivity in, the producingflow rate from, the total production from and the monetary returns froma well.

Although the present invention has been described with respect tospecific details, it is not intended that such details should beregarded as limitations on the scope of the invention, except to theextent that they are included in the accompanying claims.

1. A method for hydraulic fracturing of a well penetrating a pay zone,the pay zone having a thickness, comprising: injecting a fluid to createa vertical fracture extending a vertical distance equal to or greaterthan twice the thickness of the pay zone; and injecting a settling fluidcontaining a proppant to form a settled bank of proppant that extends inthe vertical fracture over a vertical distance that is greater thanabout one and one-half (1½) times the thickness of the pay zone.
 2. Amethod for hydraulic fracturing of a well using a Fracture FlowEnhancement treatment, the well penetrating a pay zone having athickness, comprising: using measured or estimated properties of rockaround the well, predicting the vertical extent of a hydraulic fractureusing selected properties of fracturing fluids and fracturing pumpingconditions; injecting a fluid under selected conditions to create avertical fracture extending a vertical distance greater than twice thethickness of the pay zone; and injecting a settling fluid containing aproppant to form a settled bank of proppant that extends in the verticalfracture over a vertical distance greater than one and one-half (1½)times the thickness of the pay zone.